Carbon dioxide from fossil fuel combustion and industrial processes is a major target in current emission reduction strategies. In particular, post-combustion CO2 capture from the flue gas is a key technology option for retrofitting the existing fleet of power stations. Capture of CO2 from large point sources such as fossil fueled power plants is a major concern in any strategy intended to reduce anthropogenic CO2 emissions.
Generally, approaches for the selective removal of acid gases such as carbon dioxide from these large point sources have utilized aqueous amines, such as monoethanolamine (MEA), diethanolamine (DEA), diglycol-amine (DGA), N-methyldiethanolamine (MDEA), and 2-amino-2-methyl-1-propanol (AMP). This effort has largely extended from successful uses in applications such as gas streams in natural gas, refinery off-gases and synthesis gas processing, however those particular gas streams are generally at high pressures. These approaches suffer when applied to CO2 capture from fossil-fueled based flue gases, which present large volumetric flow rates at low total pressure, temperature generally around 100-150° C., large amounts of CO2 at low partial pressure, and significant H2O content. As a result, large scale applications are hindered by a variety of challenges, such as cost of scale up, energy cost of regeneration, solvent degradation, the potential environment impacts of the solvents, and others.
Another approach to post-combustion CO2 capture from large point sources has utilized reversible CO2 capture by solid removal sorbents. These solid removal sorbents can provide advantages compared to other techniques, such as reduced energy for regeneration, greater capacity, selectivity, ease of handling, and others. In particular, the regeneration energy requirement for CO2 capture using solid removal sorbents is significantly less than the aqueos amine-based process, because of the absence of large amounts of water and comparatively lower heat capacities. A variety of solid materials have been utilized, including porous carbonaceous materials, zeolites, alumina, silica gels, and metal-organic frameworks. However, the presence of water vapor, which is an inevitable component in flue gas, may negatively affect the capacity of these removal sorbents and reduces the availability of the active surface area.
Solid removal sorbents such as zeolites and others can become easily deactivated by moisture in the gas process stream. Current state of the art CO2 removal techniques generally involve either capturing moisture with the CO2 or removing the moisture prior to capturing the CO2. Removing the moisture prior to capture can be costly in both capital and energy, since typically the moisture removal sorbent must be heated for sorbent regeneration. See e.g., U.S. patent application Ser. No. 12/419,513 by Jain, published as U.S. Pub. No. 2010/0251887, published Oct. 7, 2010; see also Ishibashi et al., “Technology for Removing Carbon Dioxide from Power Plant Flue Gas by the Physical Adsorption Method,” Energy Convers. Mgmt 37 (1996). These processes typically detail moisture removal sorbent regenerations at temperatures of at least 80° C. and in some situations up to 300° C., in order to fully regenerate the H2O removal sorbent and remove substantially all adsorbed moisture before re-use in a cycle. The additional heat required for these temperatures is supplied through some means such as power plant steam or electrical heating, and dramatically increase plant efficiencies associated with capture. In some cases, moisture removal requires more than 30% of the total energy of the CO2 removal process.
It would be advantageous if a post-combustion CO2 removal process utilizing a solid removal sorbent were available where H2O could be reduced prior to CO2 capture in a more economical manner. It would particularly advantageous if the process could utilize relatively low temperature and pressures for the H2O and CO2 sorption, mitigating the impact on overall efficiency. It would be additionally advantageous if the process could effectively utilize the low partial pressures of various gases in existing process streams and operate the cycle with an H2O removal sorbent which is only partial regenerated, in order to avoid the relatively high penalties associated the full regeneration processes typically employed.
Disclosed here is a method for the removal of H2O and CO2 from a gaseous stream such as a flue gas, where the method utilizes first and second stage regenerations to affect an overall regeneration sufficient for a cyclic operation. The first and second regenerations utilize the low partial pressures of CO2 and H2O within the process streams of the method, and are effective at relatively low temperatures and pressures. The regenerations generally act only to remove moisture layers contained in the multi layers bound to an initial monolayer on the various described H2O removal sorbents, allowing the Gibbs free energy of mixing to largely compensate for the heats of reaction, and largely avoiding the additional heats required for removal of the initial monolayer. Generally the applicable H2O sorption/desorption processes may be conducted at temperatures less than about 70° C. and pressures less than 1.5 atmospheres, with certain operations conducted at temperatures less than about 50° C.
These and other objects, aspects, and advantages of the present disclosure will become better understood with reference to the accompanying description and claims.